Oil-rim deposits account for 15 to 20 percent of production at Gazprom Neft – and their contribution is expected to increase

INTERFAX agency

Gazprom owns an enormous number of gas fields, some of which include oil-rim deposits — a thin layer of oil between a “gas cap” and water-bearing strata. The energy concern passed the right to develop its oil-rim deposits to its subsidiary, Gazprom Neft, many years ago. But the difficulty inherent in oil-rim development rendered production unviable; and Gazprom Neft had no way of getting round this.

Denis Sugaipov, CEO, Gazpromneft-Razvitiye and Head of Major Upstream Projects, Gazprom Neft

Technological developments allowed Gazprom Neft to find a way to develop these assets some time ago, with oil-rim deposits accounting for around 20 percent of the oil company’s production as early as 2018. Denis Sugaipov, CEO, Gazpromneft-Razvitiye and Head of Major Upstream Projects, Gazprom Neft, talks about how the company has made oil-rim deposits economically viable, and the current status and outlook for their development, in this interview with Interfax.

— The problem of developing oil-rim deposits at Gazprom’s fields has been around for ever, but this used to be a second — or even third-level priority. What’s happened to make them a priority for Gazprom Neft?

— Almost 10 years ago, when Gazprom’s oil fields first started being transferred to Gazprom Neft, the initial list included major projects — Novy Port, Messoyakha, the eastern block of the Orenburg field — and then, later, Prirazlomnoye. These first three, as it happened, fell into the category of oil-rim deposits, the most difficult reserves to develop. Insofar as each of these assets has major reserves, their development was deemed to be economically viable. We had to build infrastructure completely from scratch here, but it was at Novy Port, Messoyakha and Orenburg that we worked out the main technologies for developing oil-rim deposits.

Over time, though, a great deal has changed — both in terms of the macro-economic situation, and the tax element in relation to Russia’s oil industry. The situation vis-à-vis oil-rim deposits changed radically during the time in which tax concessions were introduced for oil exports. This coincided with the commissioning of the above-mentioned Gazprom Neft major assets, when it became apparent that the second phases of these projects would also be viable. So we then faced a new challenge, which was — what to do with smaller oil-rim deposits, located directly in Gazprom’s gas fields?

An oil-rim deposit cannot be separated from the main gas reservoir, and the license for an oil-rim deposit cannot be separated out — it can’t be sold or transferred. So the license will always remain with Gazprom, even though an oil company is going to have more skills and competencies in oil-rim development. Added to which, commissioning an oil-rim deposit will only ever be viable once considerable capital investment has been made in gas infrastructure. Because oil-rim deposits have considerable volumes of associated petroleum gas (APG), these oil wells become gas wells after three to five years, and the APG has to be not just utilised, but monetised.

Synergies in working with Gazprom have to be optimised in developing oil-rim deposits. Due to our key shareholder’s pre-existing as infrastructure, Gazprom Neft gained a strategic advantage here.

— So the major oil-rim deposits have been brought into production. And the remaining deposits are going to have far smaller reserves ...

— Yes, although they do have their own advantages. The second group of fields and oil-rim deposits recently transferred to Gazpom Neft from Gazprom include the Severo-Samburgskoye and Tazovskoye fields. Both of these are located next to already developed assets, in populated areas, with pre-existing infrastructure. We have now reached the point of taking the ultimate decision on investment on these two projects. We’ll be drilling horizontally branched wells with overall lengths of up to four kilometres here. Added to which, the Tazovsky field will have to do without fracking, but the Severo-Samburgskoye field, part of which involves Achimov deposits, on the other hand, will need multi-stage fracking.

The Tazovskoye and Severo-Samburgskoye are extremely challenging fields. Even 10 years ago there would have been no economic or technological basis for developing these. But today, our calculations show that there are, and that an economically viable case can be made, thanks to new kinds of horizontal drilling and the application of the excess profits tax (EPT) regime. Both of these projects fall under the EPT regime — as does Novy Port, with effect from this year.

— What contribution are the above major oil-rim projects making to the company’s total production volumes? And how might this change once new oil-rims are commissioned?

— To all intents and purposes, the Novy Port, Orenburg and Messoyakha oil-rim deposits currently account for 15 to 20 percent of production at Gazprom Neft. I repeat, in technological terms these are no less complex than any other oil-rim deposits — it’s just that their deposits are much larger, and this means certain specific infrastructure costs can be significantly reduced. Reserves at other oil-rim deposits are exponentially smaller, which is why we are looking for innovative approaches in terms of temporary infrastructure, in order to reduce costs.

The next stage in bringing oil-rim deposits into production will be projects in the Nadym-Pur-Taz area — the Tazovsky, En-Yakhinskoye, Pestsovoye, and Zapadno-Tarkosalinskoye fields, as well as oil-rim deposits at the Orenburg and Chayandinskoye fields. Gazprom Neft plans to allocate about RUB30—35 billion to finalising pilot operations and starting construction at these oil-rims. The company’s outgoings here will reach about RUB180 billion over the next three years. We expect to be launching these oil-rim deposits in 2020–2021.

As regards production volumes, the En-Yakhinskoye, Pestsovoye and Severo-Samburgskoye fields together will deliver two to three million tonnes of oil at peak production, and up to six billion cubic metres of gas. If we estimate potential volumes in their entirety, then production at the new Nadym-Pur-Taz oil-rim deposits alone could reach 13–14 million tonnes of oil equivalent (mtoe) in total. That’s a lot. Then there’s the potential of the Chayandinskoye and Orenburg fields, albeit these are at a much earlier stage. We’re currently de-mothballing at the Orenburg field, so we don’t even have provisional figures, although we’re expecting between 1.5 and two million tonnes in the early stages at Chayandinskoye.

— You mention the complexity of oil-rim deposits quite a bit, and the necessity of technological solutions in developing these. Is the company mainly using its own developments? Or have these projects been moving forward mainly thanks to the development of the oil industry?

— By way of an example: when the investment decision was taken on Novy Port and Messoyakha, the main run of the horizontal well under the reservoir management plan averaged 600 metres; the average run of a horizontal well in these fields is two kilometres. So we’ve started drilling fishbone wells here — branched horizontal wells, with fracking. And this in fields subject to the conditions of the Russian Far North.

Obviously, Gazprom Neft isn’t the only one in the industry moving in this direction — many companies have found considerable success. But we’ve been able to move forward largely thanks to our own experience. Credit has to be given to our Science and Technology Centre, responsible for managing drilling at all of the company’s fields, and helping to manage the most complex wells. Using digital and cognitive methodologies, as well as artificial intelligence (AI) reduces errors in drilling, and optimises hole-making (“stringing”) in strata. In oil-rim deposits, that’s particularly important. Because oil-rims are very thin, any emission from oil-bearing strata leads to a rapid breakthrough of gas, and we end up with a gas well instead of an oil well.

A further Gazprom Neft innovation could be said to be the use of relatively inexpensive mobile oil- and gas- treatment infrastructure — i.e., transportation centres for collecting and processing hydrocarbons. Because oil-rim deposits involve small reserves, it’s not viable to build large collection points. We’ve moved over to using mobile facilities, both using those available on the market — which we rent — and buying our own.

Typically, this means installations for up to one million tonnes of oil per year. They cut infrastructure costs drastically and, what’s even more important — increase the speed of developing oil-rim deposits. To put that in context: construction works at Novy Port started in 2011, with commercial production starting in 2016. That is, we spent five years on it; it’s pretty much the same story at Messoyakha. In the event of moving to second-stage oil-rim development, we want to cut that lead-time from five years to three. Mobile facilities make that possible. If we hadn’t made use of mobile oil-gathering then there wouldn’t be any oil-rim production at all.

— Gazprom Neft recently adopted a new long-term development strategy, to 2030. What role do oil-rim deposits play in that?

— Gazprom Neft now has a general strategic vision, in which priority projects are divided into three main groups: developing oil-rim deposits; further development on the Yamal Peninsula (everything north and south of Novy Port); and Achimov deposits. Practically all of these projects are in the Yamalo-Nenets Autonomous Okrug. Long term, we’re planning for half of all Gazprom Neft’s production to be concentrated in precisely this region.

Oil-rim deposits are at the most advanced stage. The second group concerns Achimov deposits. Part of the Severo-Samburgskoye field, and the second phase of the Tazovskoye and Yamburgskoye fields, are striking examples of Achimov deposits. We’re expecting to work out start-up operations at the Samburgskoye and Tazovskoye fields, but the Yamburgskoye field, with its deposits — estimates for which vary from one to three billion tonnes of oil equivalent (btoe) — could present a new challenge for Gazprom Neft. The scale of this project is extremely extensive — five to 20 million tonnes of oil could be produced here. We’re hoping to choose a conceptual strategy for Yamburg this year, taking a provisional investment decision next year, with a final investment decision as early as 2021.

Gazprom Neft has a number of Achimov deposits, all in all — they occur at Messoyakha, and throughout Western Siberia. The most valuable, for us, is the northern cluster — reserves in the Yamalo-Nenets Autonomous Okrug, which are estimated at several billion tonnes of oil equivalent. If we’re talking in terms of strategy after 2023 then, up to 2030, this will largely depend on developing fields with Achimov deposits.

The third group in terms of Gazprom Neft’s new projects concerns development in Yamal — fields around Novy Port, which also have enormous reserves, of up to one billion tonnes of oil equivalent. The company has a logistical advantage here — an oil-shipment terminal, and we’ve also started building a pipeline. Gazprom Neft was the first into this region; it’s going to be hard for anyone else to compete.

Taking a decision on which of these new projects is likely to be the top priority is something Gazprom Neft is going to have to address as soon as one or two years’ time.

— But why no mention of resources in Eastern Siberia? Gapzrom Neft’s starting work on developing the Chayanda oil-rim deposits, and is undertaking geological exploration on the Chona project.

— The quality of the reserves we have built up in Eastern Siberia is extremely challenging. Thus far, we mainly associate Gazprom Neft’s development in Eastern Siberia with success in developing oil-rim deposits at the Chayandinskoye field. If we succeed in reaching a sufficiently high level of oil production there then the option of creating a cluster, connecting the Chonskoye and Chayandinskoye fields, might arise. At which point it might be possible to talk about Gazprom Neft’s development in Eastern Siberia.

Again though, we are considering a partnership on the Chona project, and are hoping to reach agreement with a potential investor as soon as possible. But involving a partner does not guarantee success in geological prospecting on a project of this difficulty. It just reduces the risks. Success depends on how we deal with infrastructure and geology at the Chayandinskoye field, and what we can do in terms of synergies across these two fields.

In the meantime, pilot works are continuing at Chayandinskoye. We’ll start drilling a horizontal well, independently, this year, which we’ll be continuing next year. Our job here is to confirm the preconditions for cumulative production from Chayandinskoye oil-rim deposits, from a single well. In the event of a positive outcome, drilling another 100–110 wells might be possible at this field. We’re hoping an investment decision on the Chayandinskoye field will be taken in 2020.

We’ve made no secret of the fact that not all oil-rim deposits have confirmed their viability. The Zapolyarnoye field is an example of this, where we’ve undertaken pilot works, drilled several wells and realised that we need to stop. There aren’t the reserves we were counting on there. Which is to say, the risks associated with oil-rim deposits are always there.

— You’re also responsible for managing Gazprom Neft’s major projects internationally. A key one here being in Badra, Iraq. The company cut peak production here due to the complex geology and high costs, asking local government to agree to a new development plan. What’s the Iraqi government’s position on developing the Badra project?

— Yes, we’ve discussed an updated field development plan with local government in Iraq several times. We were finally able to agree on this at the end of last year. Under the new plan, daily production on this project is now set at 75,000 barrels per day (bpd) — the original plan having assumed a gradual increase in production to 170,000 bpd, before Gazprom Neft suggested it remain at the current level of 75,000 bpd.

In terms of approved production levels, our argument was this: at the initial stage we had information on one exploratory well, provided by the Iraqi side. That information was not endorsed during the course of subsequent drilling-out. The main discrepancy with the initial data lay in the fact that we were expecting to find two oil-bearing reservoirs at the Badra field, with provisional reserves in place of about 110 million tonnes of oil. Ultimately one of these strata turned out to be completely unproductive, which reduced reserves practically two-fold.

— So then what’s the immediate outlook for developing the Badra field?

— At the very beginning we were planning to drill 22 wells, as well as drilling a horizontal well, which would have increased production. But these plans coincided with certain limitations under the OPEC+ deal, and the Iraqi government did not accept our proposals.

Obviously, though, putting infrastructure in place at Badra will need to be supplemented with additional drilling. Added to which, in terms of economics, there’s not that much time left for making that happen. If we leave everything as it is now, and only come back to drilling in three years’ time, that’s going to be even less economically viable, because the duration of the contact will be drawing in. We’ve now resumed negotiations with Iraq on drilling another three wells.

Badra remains an effective project for Gazprom Neft. Certainly — if judged against Russian project criteria — it’s not as effective as we might like. But we’re looking at Badra from a different angle. First of all, the company has acquired a great many skills and competencies in working with foreign partners in Iraq. Our specialists working here now have international experience. Secondly, the Badra project is profitable. And compared to other international companies’ projects in Iraq that would seem to be enough.

And Iraq itself is a very promising region for Gazprom Neft. We are looking at new projects here, not just projects close to Badra. We looking at all of southern Iraq, as well as the central regions. We’re hoping the country’s government takes a positive view of our continuing our work here, and will be able to offer Gazprom Neft some interesting options on hydrocarbon blocks. We’re working with the Iraqi government to that end.

— Why is Gazprom Neft withholding information on its discoveries in Kurdistan?

— It’s possible those projects we’re involved in in Kurdistan — Sarqala, Shakal and Halabja — were somewhat overvalued initially. What is well known is that we’ve already taken the decision to quit Halabja.

Wells were recommissioned at the Shakal block last year — the result of which seriously dampened expectations. We’ve extended the period for further field appraisal with the Kurdish side in order to assess whether it’s worth being involved at all. We’ll be taking a decision by the end of this year — do we stay or not.

We’re continuing to work at Sarqala — we’ve just finished drilling a third well, which has confirmed strata productivity. This well will be brought into production before the end of March, and is yielding about 1,200 tonnes of oil per day. That’s a good outcome. The Sarqala-3 well is a milestone because any decision on further drilling depends on the outcomes here. So the Sarqala project is going to plan. Production here was previously 25,000 bpd; following the commissioning of the third well, it’s increased to 35,000. Generally, we’re hoping to maintain peak production at Sarqala at more than 40,000 bpd.

So we’re constantly investigating new options — primarily those having synergies with existing projects in the country. At the same time, we’re not focussed on any quantitative goals in terms of development in Iraq or Iraqi Kurdistan — the key to our international business is developing a sustainable and economically viable business, in the long term.

Gazprom Neft’s strategy abroad is to act on a point-by-point basis. The company isn’t looking to produce large volumes of oil outside of the Russian Federation — we’ve got a great many good Russian projects. International experience is important in improving the qualifications of our own specialists and in building a wide range of international contacts.